Exhibit 99.1

 

 

 

Antero Resources Reports Third Quarter 2017 Financial and Operational Results

 

Denver, Colorado, November 1, 2017—Antero Resources Corporation (NYSE: AR) (“Antero” or the “Company”) today released its third quarter 2017 financial and operational results. The relevant condensed consolidated financial statements are included in Antero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, which has been filed with the Securities and Exchange Commission (the “SEC”).

 

Highlights Include:

 

·                  Net daily gas equivalent production averaged a record 2,317 MMcfe/d, a 24% increase over the prior year quarter

·                  Includes record liquids production of 112,393 Bbl/d, a 38% increase over the prior year quarter

·                  Realized natural gas price of $2.71 per Mcf, a $0.29 differential to the average Nymex natural gas price before hedging. This includes a net $0.26 per Mcf negative impact from two contractual disputes on natural gas sales contracts where Antero expects to recover damages as detailed further below.

·                  Realized C3+ NGL price of $28.92 per barrel before hedging, or 60% of the average WTI oil price

·                  Realized natural gas equivalent price of $3.39 per Mcfe including NGLs, oil and hedges

·                  Liquids revenue of $251 million, comprising 38% of total product revenues, a Company record

·                  GAAP net loss of $135 million, or $(0.43) per share, compared to net income of $238 million, or $0.78 per share, in the prior year quarter

·                  Adjusted EBITDAX of $336 million, a 10% decrease compared to the prior year quarter and a 5% increase sequentially. This Adjusted EBITDAX does not include the $47 million impact from the contractual disputes detailed below.

·                  Successfully monetized over $1 billion of non-E&P assets through combination of the sale of Antero Midstream common units and the restructuring of the hedge portfolio

·                  Entered into a new upstream credit facility with a borrowing base of $4.5 billion and lender commitments of $2.5 billion

 

Commenting on the quarter and long-term outlook, Paul Rady, Chairman and CEO, said, “We took a number of steps during the quarter to delever the balance sheet, and have positioned Antero to generate attractive growth and returns while spending within cash flow in 2018 and beyond. This is a testament to the capital efficiencies and EUR improvements that we have achieved to date.  Through increased EURs and lower well costs, we have been able to reduce our drilling and completion capital spending plans over the 2018 through 2020 period by approximately $1.5 billion while delivering the same production growth.  Importantly, this production growth includes rapid NGL production growth, providing us with substantial upside exposure to a continuing rise in liquids pricing.  The combination of the sizeable reduction in capital needs with the increased liquids cash flow provides Antero with declining leverage and an improving balance sheet.  This trend positions Antero to be able to return capital to shareholders in the coming years, subject to Board review and approval.”

 

Recent Developments

 

Antero Three Year Outlook

 

Based on the Company’s internal development plan, Antero is targeting a compound annual production growth rate of 20% over the four year period of 2017 to 2020, with a drilling and completion capital program that is self-funded with E&P stand-alone cash flow.  The current development plan assumes flat $3.00/MMBtu NYMEX gas and $54/Bbl WTI oil, in line with 2018 strip pricing, and a targeted drilling and completion capital program of approximately $1.3 billion in 2018, $1.5 billion in 2019 and $1.5 billion in 2020.  These capital budget targets have not been approved by Antero’s Board. The $1.3 billion targeted drilling and completion capital program in 2018 reflects the third consecutive year of maintaining a flat capital program while still delivering top tier production

 

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growth.  Additionally, as a result of increased EURs, lower well costs, and land consolidation efforts supporting long lateral drilling, this development plan represents a reduction of 200 wells and approximately $1.5 billion in capital through 2020 when compared to the prior development plan targeting the same production growth. This capital plan focuses on liquids-rich, high margin locations designed to deliver significant per share cash flow and production growth over the next three years.

 

Updated NGL Pricing Realizations Forecast

 

Based on public company disclosure, Antero is now the largest NGL producer in the U.S. with 105,609 Bbl/d produced in the third quarter of 2017, representing 37% growth compared to the prior year quarter.  This includes 75,290 Bbl/d of C3+ NGLs and 30,319 Bbl/d of recovered ethane. Antero’s average realized C3+ NGL price before hedging for the third quarter of 2017 was $28.92 per barrel, or 60% of the average Nymex WTI oil price, which represents a 65% increase as compared to the prior year quarter.  Due to continued strength in domestic C3+ NGL markets and export demand, Antero is forecasting realizations of 70% to 75% of WTI on its C3+ NGL production for the fourth quarter of 2017. In addition, based on strip pricing, Antero is forecasting realizations of approximately $35/Bbl, or 65% of WTI for 2018. Based on current strip prices and production targets, Antero estimates that cash flow from liquids production is forecast to be approximately $390 million higher in 2018 as compared to 2017.

 

Completion of $1 Billion Delevering Program

 

Antero previously announced that it monetized over $1 billion of non-exploration and production (“E&P”) assets in September 2017. This includes the sale of 10 million common units representing limited partner interests in Antero Midstream Partners LP (NYSE:AM) (“Antero Midstream”) and the restructuring of a portion of its commodity hedge portfolio.  Proceeds from the monetization program were used to repay credit facility borrowings.  The monetization program was tax-efficient due to the utilization of a portion of Antero’s $1.6 billion of net operating losses.  Antero Resources’ stand-alone E&P net debt to last twelve months stand-alone adjusted EBITDAX ratio was 2.6x and its consolidated net debt to last twelve months consolidated adjusted EBITDAX ratio was 3.0x as of September 30, 2017, a reduction of 0.4x and 0.6x, respectively, as compared to June 30, 2017.  For a description of stand-alone E&P net debt and Adjusted EBITDAX and reconciliations to their nearest comparable GAAP measures, please read “Non-GAAP Financial Measures.”

 

New Credit Facility Agreement

 

Antero has entered into a new upstream credit facility with a borrowing base of $4.5 billion and lender commitments of $2.5 billion.  The $4.5 billion borrowing base under the credit facility represents a $250 million reduction from the Company’s previous borrowing base of $4.75 billion net of the $750 million hedge monetization executed in September 2017.  Lender commitments were reduced by $1.5 billion from the previous commitments of $4.0 billion.  The decision to materially reduce lender commitments reflects Antero’s current essentially undrawn balance on its facility and its plan to primarily fund its drilling program with cash flow from operations.  The new credit facility matures in October 2022, subject to certain exceptions, and includes fall away covenants that are triggered if and when Antero is assigned an investment grade credit rating by the rating agencies.  The credit facility is supported by a bank syndicate, which is co-led by JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A.  The bank syndicate is comprised of 24 banks, 23 of which were lenders in the prior credit facility.

 

Commenting on liquids exposure, the recent delevering program and the new credit facility, Glen Warren, President and CFO, said, “As the largest NGL producer in the U.S. during the third quarter, Antero continues to benefit from the significant increase in NGL pricing that has occurred over the last several months.  NGL production has been a key pillar of our business strategy for a number of years and we believe that it will be a key differentiator for Antero for many years to come. The Mariner East 2 NGL pipeline project will be completed soon and export demand continues to grow.  The increase in cash flow associated with our liquids-rich drilling inventory is one of the many drivers behind our decision to lower commitments on our new credit facility to $2.5 billion.  The $1.5 billion reduction in commitments not only reflects the fact that we are essentially undrawn on our facility today, but is also a function of Antero’s plan to primarily fund our drilling program with cash flow from operations and distributions from our ownership in Antero Midstream.”

 

Contract Disputes

 

During the third quarter of 2017, Antero’s realized natural gas price was negatively impacted by contract disputes with two counterparties related to two separate long-term natural gas sales agreements.

 

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WGL’s Natural Gas Sales Contract

 

Antero is currently contracted to sell and deliver natural gas volumes varying between 500,000 MMBtu/d and 600,000 MMBtu/d to Washington Gas Light Company, a regulated utility based in Washington, D.C., and WGL Midstream, Inc. (collectively, “WGL”) at a delivery point in Braxton, West Virginia where the Stonewall Pipeline interconnects with Columbia’s WB Pipeline. Beginning in April 2017, WGL failed to take delivery of a portion of the contracted sales volume in direct violation of the contract terms due to WGL’s lack of downstream primary firm transportation capacity to move the purchased gas.  WGL’s nonperformance under the contract has resulted in Antero selling approximately 380,000 MMBtu/d, on average, of natural gas volumes that WGL was obligated to take at other regional indices at a lower price relative to the contracted price.  Per its contracts, Antero has invoiced WGL for cover damages resulting from reselling the contracted natural gas at lower prices, which WGL has failed to pay.  For the three months ended September 30, 2017, this has resulted in a loss of approximately $40 million net to Antero and resulted in a $(0.22)/Mcf negative impact to Antero’s total company realized natural gas pricing.  Year to date through September 30, 2017, cover damages net to Antero have totaled approximately $55 million.  Antero will continue to vigorously seek recovery of its cover damages, as clearly defined in the contracts, and other unpaid amounts as part of its claims against WGL. Antero has not accrued for these amounts in the Company’s financial statements.

 

As it relates to this contractual dispute, WGL and Antero have also recently been involved in two previous lawsuits related to pricing and delivery points on these contracts.  In the first lawsuit, which was ultimately referred to arbitration, the arbitration panel ruled in Antero’s favor and the award was confirmed by the Colorado District Court in April 2017.  In the second lawsuit, the Colorado District Court dismissed with prejudice WGL’s claims against Antero and found that Antero had not breached its contracts with WGL.  For further information on this dispute, please see note 10 to Antero’s condensed consolidated financial statements included in Antero’s Form 10-Q for the period ending September 30, 2017.

 

South Jersey Natural Gas Sales Contract

 

Antero’s third quarter 2017 realized gas price was also negatively impacted by an ongoing breach of contract by South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, “SJGC”) related to two long term natural gas sales contracts that total 80,000 MMBtu/d. The price for natural gas sales was specifically based on the Platt’s Columbia Appalachia Index outlined in the contracts.  Beginning in October 2014, SJGC began short paying Antero based on price indices unilaterally selected by SJGC and not the Platt’s Columbia Appalachia Index specified in the contracts.  SJGC claimed that a market disruption event had occurred and, as a result, a new index price was required to be determined by the parties. Antero filed a lawsuit against SJGC in the U.S. District Court in Colorado to recover against SJGC for their breach of the contracts. In early May 2017, a jury returned a unanimous verdict finding in favor of Antero’s positions in the lawsuit against SJGC. In July 2017, final judgment on the jury’s unanimous verdict was entered by the court. SJGC continues to short pay the Company while it challenges the court’s final judgment, resulting in approximately $7 million in damages net to Antero and a $(0.04)/Mcf negative impact to Antero’s total company realized natural gas pricing for the three months ended September 30, 2017.  From January 1, 2015 through September 30, 2017, damages net to Antero total approximately $47 million. Antero has not accrued for this amount in the Company’s financial statements.  Antero will continue to vigorously seek recovery from SJGC of all underpayments and damages, including those short payments continuing after the court’s final judgment.  For further information on this dispute, please see note 10 to Antero’s condensed consolidated financial statements included in Antero’s Form 10-Q for the period ending September 30, 2017.

 

In combination, the Company does not expect a material impact to its realized natural gas pricing and cash flow beyond year-end 2017 from these contractual disputes due to the start-up of the Cove Point LNG export facility expected in the first quarter of 2018, additional takeaway capacity expected to be placed in service throughout 2018, and narrower regional basis differentials based on current strip pricing.

 

For the third quarter and first nine months of 2017, these two disputes resulted in the following impact to Antero’s realized natural gas pricing:

 

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		As Reported			As Adjusted For WGL and South Jersey Gas Contract Disputes			Variance
Three months ended 9/30/17
Realized Natural Gas Price ($/Mcf)		$	2.71		$	2.97		$	(0.26	)
Discount to Nymex ($/Mcf)		$	(0.29	)	$	(0.03	)	$	(0.26	)
Nine months ended 9/30/17
Realized Natural Gas Price ($/Mcf)		$	3.06		$	3.18		$	(0.12	)
Discount to Nymex ($/Mcf)		$	(0.11	)	$	0.01		$	(0.12	)

 

Revised 2017 Guidance

 

As a result of the two aforementioned contract disputes and the significant increase in realized NGL pricing both on an absolute basis and on a relative basis to WTI oil, Antero is revising its 2017 realized pricing guidance and is also providing new guidance for the fourth quarter of 2017.

 

Full Year 2017 Guidance

 

		2017 - OLD						2017 - NEW
Realized Pricing (Unhedged)		Low			High			Low			High
Natural Gas Differential to Nymex Henry Hub ($/Mcf)(1)(2)		$	0.00		$	0.10		$	(0.15	)	$	(0.10	)
Oil Realized Price Differential to Nymex WTI Oil ($/Bbl)		$	(7.00	)	$	(9.00	)	$	(7.00	)	$	(6.50	)
C3+ NGL Price (% of Nymex WTI) (1)		50		%	55		%	57.5		%	62.5		%

 

4Q 2017 Guidance

 

		4Q 2017
Realized Pricing (Unhedged)		Low			High
Natural Gas Premium/(Discount) to Nymex Henry Hub ($/Mcf)(1)(2)		$	(0.20	)	$	(0.15	)
Oil Realized Price Differential to Nymex WTI Oil ($/Bbl)		$	(6.00	)	$	(5.00	)
C3+ NGL Price (% of Nymex WTI) (1)		70		%	75		%
Consolidated Adjusted EBITDAX ($MM) (3)(4)		$	410		$	440

 

(1)         Based on strip pricing as of October 27, 2017, before hedging.

(2)         Includes Btu upgrade as Antero’s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average.

(3)         Based on strip pricing as of October 27, 2017.

(4)         For a description of the non-GAAP financial measure Adjusted EBITDAX, please read “Non-GAAP Financial Measures.”  Antero has not included a reconciliation of consolidated Adjusted EBITDAX to net income for the fourth quarter of 2017 because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise.  Antero is able to forecast interest expense and depreciation, depletion, amortization and accretion expense for the fourth quarter of 2017 between a range of $63 million and $67 million and $210 million and $220 million, respectively, each of which is a reconciling item between Adjusted EBITDAX and net income.  However, Antero has a significant portfolio of commodity derivative contracts that it does not account for using hedge accounting, and forecasting unrealized (gains) losses on this portfolio is impracticable and imprecise due to the price volatility of the underlying commodities.

 

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Third Quarter 2017 Financial and Operating Results

 

As of September 30, 2017, Antero owned a 53% limited partner interest in Antero Midstream.  Antero Midstream’s results are consolidated with Antero’s results.

 

For the three months ended September 30, 2017, the Company reported a net loss of $135 million on a GAAP basis, or $0.43 per basic and diluted share, compared to net income of $238 million, or $0.78 per basic and $0.77 per diluted share, in the third quarter of 2016.  The net loss for the third quarter of 2017 included the following items:

 

·                  Non-cash loss on unsettled hedges of $878 million

·                  Gain on hedge monetization of $750 million

·                  Non-cash equity-based compensation expense of $26 million

·                  Impairment of unproved properties of $41 million

·                  Income tax effect of these reconciling items of $(74) million

 

Excluding the items detailed above, the Company’s results for the third quarter of 2017 were as follows:

 

·                  Adjusted net loss of $14 million, or $0.04 per basic and diluted share, a 125% decrease compared to adjusted net income of $55 million in the third quarter of 2016

·                  Adjusted EBITDAX of $336 million, a 10% decrease compared to the third quarter of 2016

 

Antero’s net daily production for the third quarter of 2017 averaged 2,317 MMcfe/d, including a record 112,393 Bbl/d of liquids (29% liquids by volume).  Third quarter 2017 production represents an organic production growth rate of 24% from the third quarter of 2016 and a 5% increase compared to the second quarter of 2017.  Third quarter 2017 C3+ natural gas liquids (“NGLs”) and oil production averaged 75,290 Bbl/d and 6,784 Bbl/d, respectively.  Propane made up approximately 43,000 Bbl/d of the C3+ NGL production volume.  Ethane (C2) production averaged 30,319 Bbl/d while leaving approximately 124,000 Bbl/d of ethane in the natural gas stream.  Total liquids production of 112,393 Bbl/d for the third quarter of 2017 represents an organic production growth rate of 38% and 9% as compared to the third quarter of 2016 and second quarter of 2017, respectively.  Liquids revenues made up approximately 38% of total product revenues during the third quarter of 2017, an increase from 25% of total product revenues during the prior year quarter.

 

Antero’s average natural gas price before hedging decreased by 5% from the prior year quarter to $2.71 per Mcf, a $0.29 differential to the average Nymex natural gas price for the period.  Excluding the $(0.26) negative impact from the aforementioned natural gas contract disputes, Antero’s average natural gas price before hedging would have been $2.97 per Mcf, a $0.03 negative differential to the average Nymex natural gas price for the period.  Antero’s average realized natural gas price after hedging for the third quarter of 2017 was $3.37 per Mcf, a $0.37 premium to the Nymex average natural gas price for the period, and a 22% decrease compared to the prior year quarter.  During the third quarter, Antero realized a cash settled natural gas hedge gain of $100 million on swaps that matured during the quarter, or $0.66 per Mcf compared to $184 million, or $1.44 per Mcf in the prior year quarter.

 

The Company’s average realized C3+ NGL price before hedging for the third quarter of 2017 was $28.92 per barrel, or 60% of the average Nymex WTI oil price, which represents a 65% increase as compared to the prior year quarter.  Further, the Company’s average realized C3+ price was $33.23 per barrel ($0.79 per gallon) for the month of September as NGL prices improved throughout the third quarter.  The improvement in realized C3+ NGL pricing is primarily due to an increase in Mont Belvieu pricing driven by exports combined with an improvement in local differentials.  During the quarter, Antero realized a cash settled C3+ NGL hedge loss of $40 million, or $5.77 per barrel. Antero’s average realized C3+ NGL price including hedges was $23.15 per barrel, a 16% increase compared to the third quarter of 2016.  The Company’s average realized ethane price before hedging for the third quarter of 2017 was $0.21 per gallon, or $8.68 per barrel.  During the quarter, Antero realized a cash settled ethane hedge loss of $0.4 million, or $0.15 per barrel.  Antero’s average realized ethane price including hedges for the third quarter of 2017 was $0.20 per gallon, or $8.53 per barrel.  The average realized oil price before hedging was $42.50 per barrel, a $5.66 differential to Nymex WTI for the period and a 22% increase as compared to the third quarter of 2016.  Antero’s average realized oil price including hedges was $45.40 per barrel, a $2.76 differential to Nymex WTI for the period.  During the quarter, Antero realized a cash settled hedge gain on oil of $2 million, or $2.90 per barrel.

 

Antero’s average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased from the prior year quarter by $0.28 to $3.10 per Mcfe. Liquids production increased equivalent pricing for dry gas by $0.39 per Mcfe.  The Company’s average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, decreased by 14% to $3.39 per Mcfe compared to the prior year quarter.  For the third quarter of 2017, Antero realized a total cash settled hedge gain on all products of $61 million, or $0.29 per Mcfe.

 

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Total operating revenue for the third quarter of 2017 was $648 million as compared to $1.1 billion for the third quarter of 2016.  Operating revenue for the third quarter of 2017 included an $878 million non-cash loss on unsettled hedges, while the third quarter of 2016 included a $334 million non-cash gain on unsettled hedges.  The non-cash loss on unsettled hedges was primarily driven by the $750 million hedge monetization where Antero reduced the average fixed index price on some of its 2018 through 2022 natural gas hedges while maintaining the total volume hedged.  Liquids production contributed 38% of total product revenues before hedges in the third quarter of 2017 as compared to 25% in the prior year quarter.  For a reconciliation of revenue excluding unrealized hedge (gains) losses to operating revenue, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”

 

Marketing revenue for the third quarter of 2017 was $51 million.  Antero’s marketing revenue was primarily associated with the sale of third party gas purchased to utilize the Company’s excess firm transportation capacity on the Tennessee, Columbia Gas and Rockies Express Pipelines.  Marketing expense for the third quarter of 2017 was $79 million, including costs related to excess capacity and the cost of purchasing third party gas.  Net marketing expense was $28 million, or $0.13 per Mcfe, for the third quarter of 2017, representing a $0.03 per Mcfe increase from the third quarter of 2016.

 

Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) for the third quarter of 2017 was $1.54 per Mcfe, which was in line with the prior year quarter.  The per unit cash production expense for the quarter included $0.11 per Mcfe for lease operating costs, $1.32 per Mcfe for gathering, compression, processing and transportation costs and $0.11 per Mcfe for production and ad valorem taxes.  Per unit general and administrative expense for the third quarter of 2017, excluding non-cash equity-based compensation expense, was $0.17 per Mcfe, a 6% decrease from the third quarter of 2016, driven by a 24% increase in production.  Per unit depreciation, depletion and amortization expense decreased 16% from the prior year quarter to $0.97 per Mcfe, primarily driven by increases in our estimated recoverable reserves, improved well performance, and decreases in our per-unit development costs.  For the Marcellus alone, per unit depreciation, depletion and amortization expense also decreased 16% from the prior year quarter to $0.83 per Mcfe.

 

Adjusted EBITDAX of $336 million for the third quarter of 2017 represents a 10% decrease compared to the prior year quarter.  Adjusted EBITDAX does not include $750 million of realized gains from the partial monetization of certain natural gas hedges or $47 million impact from the natural gas contract disputes.  Adjusted EBITDAX margin for the quarter was $1.58 per Mcfe, representing a 27% decrease from the prior year quarter.  For the third quarter of 2017, cash flow from operations was $1.0 billion, a 220% increase from the prior year quarter.  Cash flow from operations before changes in working capital was $1.0 billion, a 228% increase from the third quarter of 2016.

 

Adjusted EBITDAX is a non-GAAP financial measure.  For a description of Adjusted EBITDAX, Adjusted EBITDAX margin, as well as cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read “Non-GAAP Financial Measures.”

 

The following table details the components of average net production and average realized prices for the three months ended September 30, 2017:

 

		Three Months Ended September 30, 2017
		Gas (MMcf/d)		Oil (Bbl/d)		C3+ NGLs (Bbl/d)		Ethane (Bbl/d)		Combined Gas Equivalent (MMcfe/d)
Average Net Production		1,643		6,784		75,290		30,319		2,317

 

		Gas ($/Mcf)			Oil ($/Bbl)			C3+ NGLs ($/Bbl)			Ethane ($/Bbl)			Combined Gas Equivalent ($/Mcfe)
Average Realized Prices
Average realized price before settled derivatives		$	2.71		$	42.50		$	28.92		$	8.68		$	3.10
Settled derivatives		0.66			2.90			(5.77		)	(0.15		)	0.29
Average realized price after settled derivatives		$	3.37		$	45.40		$	23.15		$	8.53		$	3.39
Nymex average price		$	3.00		$	48.16								$	3.00
Premium / (Differential) to Nymex		$	0.37		$	(2.76	)							$	0.39

 

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Marcellus Shale — Antero completed and placed on line 31 horizontal Marcellus wells during the third quarter of 2017 with an average lateral length of 9,500 feet.  During the period, Antero drilled an average of 4,884 lateral feet per day, which represents a 42% increase compared to 2016.  Out of the 31 wells completed in the third quarter, 25 have been on line for more than 30 days and had an average 30-day rate on choke of 17 MMcfe/d (17% liquids), assuming 25% ethane recovery.

 

Current average well costs are $0.91 million per 1,000 feet of lateral in the Marcellus assuming a 2,000 pounds of proppant per foot completion.  Average drilling days from spud to final rig release was 12 days in the third quarter of 2017, a 20% reduction from 2016.  Antero is currently operating five drilling rigs and three completion crews in the Marcellus Shale.

 

In early July 2017, Antero drilled its longest laterals to date in the Marcellus, with three laterals averaging 14,000 feet. These wells are expected to be completed during the fourth quarter of 2017 and placed to sales in the first quarter of 2018.  Additionally, Antero completed a four-well pad using 2,500 pounds of proppant per foot and with an average lateral of 11,100 feet, that had a 90-day rate of 20 MMcfe/d per well including 921 Bbl/d of NGLs and 31 Bbl/d of oil, and an unprocessed EUR of approximately 2.2 Bcf/1,000’ (2.7 Bcfe/1,000’ assuming 25% ethane recovery).  Antero also put to sales another four-well pilot pad that was completed using 2,500 pounds of proppant per foot and had an average lateral of 5,400 feet. The pad delivered an average 90-day rate of 12 MMcfe/d per well including 438 Bbl/d of NGLs and an unprocessed EUR of approximately 2.3 Bcf/1,000’ (2.8 Bcfe/1,000’ assuming 25% ethane recovery).

 

Furthermore, in the first quarter of 2017, Antero completed a four-well pad using 2,000 pounds of proppant per foot and with an average lateral length of 11,100 feet, that had a 90-day rate of 22.4 MMcfe/d per well (30% liquids) and an unprocessed EUR of approximately 2.2 Bcf/1,000’ (2.6 Bcfe/1,000’ assuming 25% ethane recovery).  This pad included a 14,000 foot lateral that had a 90-day rate of 27.1 MMcfe/d (30% liquids).

 

Ohio Utica Shale — Antero completed and placed on line six horizontal Utica wells during the third quarter of 2017 with an average lateral length of approximately 9,600 feet.  During the period, Antero drilled four 17,000’ laterals and set a record for drilling its longest lateral to date at 17,445 feet.  This lateral was drilled within a 7 foot target zone and was drilled in five days.  The wells are expected to be placed to sales in the second quarter of 2018.

 

Current average well costs are $0.99 million per 1,000 feet of lateral in the Ohio Utica assuming a 2,000 pounds of proppant per foot completion.  Antero is currently operating one drilling rig and one completion crew in the Utica Shale.  Upon Rover phase 1B being placed in service, Antero expects to turn in line two dry focused Ohio Utica pads that total ten wells.

 

Antero Midstream Financial Results

 

Antero Midstream results were released today and are available at www.anteromidstream.com.

 

For the three months ended September 30, 2017, Antero Midstream reported revenues of $194 million, comprised of $101 million from the Gathering and Processing segment and $93 million from the Water Handling and Treatment segment. Revenues increased 29% compared to the prior year quarter, driven by growth in throughput volumes and fresh water delivery volumes. Water Handling and Treatment segment revenues include $45 million from wastewater handling and high rate water transfer services provided to Antero Resources, which is billed at cost plus 3%.

 

Direct operating expenses for the Gathering and Processing and Water Handling and Treatment segments were $11 million and $52 million, respectively, for a total of $63 million compared to $33 million in direct operating expenses in the prior year quarter. Water Handling and Treatment direct operating expenses include $44 million from produced water handling and high rate water transfer services.  General and administrative expenses including equity-based compensation were $14 million, a $1 million increase compared to the third quarter of 2016.  General and administrative expenses excluding equity-based compensation were $7 million during the third quarter of 2017, in line with the third quarter of 2016.  Total operating expenses were $111 million, including $31 million of depreciation and $3 million of accretion of contingent acquisition consideration.

 

Net income for the third quarter of 2017 was $81 million, a 15% increase compared to the prior year quarter. Net income per limited partner unit was $0.33 per unit, an 11% decrease compared to the prior year quarter. Adjusted EBITDA was $128 million, a 16%

 

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increase compared to the prior year quarter. The increase in net income and Adjusted EBITDA is primarily driven by increased throughput and fresh water delivery volumes. Adjusted EBITDA for the quarter included $4 million in distributions from Stonewall Gathering LLC (“Stonewall”) and the processing and fractionation joint venture.  Cash interest paid was $21 million. Decrease in cash reserved for bond interest during the quarter decreased $9 million and cash reserved for payment of income tax withholding upon vesting of Antero Midstream equity-based compensation awards was $2 million. Maintenance capital expenditures during the quarter totaled $11 million and distributable cash flow was $104 million, resulting in a DCF coverage ratio of 1.3x.

 

Antero Midstream Distribution

 

The Board of Directors of Antero Midstream Partners GP LLC, the general partner of Antero Midstream, declared a cash distribution of $0.34 per unit ($1.36 per unit annualized) for the third quarter of 2017. The distribution represents a 28% increase compared to the prior year quarter and a 6% increase sequentially.  The distribution is Antero Midstream’s eleventh consecutive quarterly distribution increase since its initial public offering in November 2014 and will be payable on November 16, 2017 to unitholders of record as of November 1, 2017.

 

Stand-alone Balance Sheet and Liquidity

 

As of September 30, 2017, Antero’s stand-alone total debt and net debt were $3.4 billion, of which $25 million were borrowings outstanding under the Company’s revolving credit facility. Total lender commitments under the new upstream credit facility are $2.5 billion.  Reduced for $700 million in letters of credit outstanding, the company had $1.8 billion in available stand-alone liquidity as of September 30, 2017.  Antero Resources’ stand-alone E&P net debt to last twelve months adjusted EBITDAX ratio was 2.6x as of September 30, 2017. For a reconciliation of stand-alone net debt to stand-alone total debt, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”

 

Consolidated Balance Sheet and Liquidity

 

As of September 30, 2017, Antero’s consolidated total debt and net debt was $4.5 billion, of which $452 million were borrowings outstanding under the Company’s and Antero Midstream’s revolving credit facilities. Total borrowing capacity under these two new facilities is now $4.0 billion.  Reduced for $700 million in letters of credit outstanding, the company had $2.9 billion in available consolidated liquidity as of September 30, 2017.  Antero Resources’ consolidated net debt to last twelve months consolidated Adjusted EBITDAX ratio was 3.0x as of September 30, 2017.  For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”

 

Third Quarter 2017 Capital Spending

 

Antero’s drilling and completion costs for the three months ended September 30, 2017 were $317 million.  In addition, the Company invested $52 million for land.  Antero Midstream invested $99 million for gathering and compression systems and $48 million for water infrastructure projects, including $33 million on the Antero Clearwater Treatment Facility.  Investments in unconsolidated affiliates for Antero Midstream’s processing and fractionation joint venture were $26 million during the quarter.

 

Hedge Position

 

Antero currently has hedged 2.9 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from October 1, 2017 through December 31, 2023 at an average index price of $3.36 per MMBtu.  At September 30, 2017, the Company’s estimated fair value of commodity derivative instruments was $1.2 billion.

 

The following table summarizes Antero’s hedge position as of September 30, 2017:

 

Period		Natural Gas MMBtu/d		Average Index price ($/MMBtu)			Liquids Bbl/d		Average Index price
4Q 2017:
Nymex Henry Hub		1,370,000		$	3.46		—		—
CGTLA		420,000		$	4.37		—		—
Chicago		70,000		$	4.68		—		—
Propane MB ($/Gal)		—		—			27,500		$	0.40
Ethane MB ($/Gal)		—		—			20,000		$	0.25
Nymex WTI ($/Bbl)		—		—			3,000		$	54.75
Total		1,860,000		$	3.71		50,500		N/A		(1)
2018:
Nymex Henry Hub		2,002,500		$	3.50		—		—
Propane MB ($/Gal)		—		—			3,000		$	0.67
Nymex WTI ($/Bbl)		—		—			1,000		49.96
2019 Nymex Henry Hub		2,330,000		$	3.50		—		—
2020 Nymex Henry Hub		1,417,500		$	3.25		—		—
2021 Nymex Henry Hub		710,000		$	3.00		—		—
2022 Nymex Henry Hub		850,000		$	3.00		—		—
2023 Nymex Henry Hub		90,000		$	2.91		—		—

 

8

 

(1)         Average index price is not applicable as 2017 liquids hedges include propane, ethane and oil hedges.

 

Conference Call

 

A conference call is scheduled on Thursday, November 2, 2017 at 9:00 am MT to discuss the quarterly results.  A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter.  To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference “Antero Resources”. A telephone replay of the call will be available until Friday, November 10, 2017 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10111894.

 

A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com.  The webcast will be archived for replay on the Company’s website until Friday, November 10, 2017 at 9:00 am MT.

 

Presentation

 

An updated presentation will be posted to the Company’s website before the November 2, 2017 conference call.  The presentation can be found at www.anteroresources.com on the homepage.  Information on the Company’s website does not constitute a portion of this press release.

 

Non-GAAP Financial Measures

 

Revenue excluding unrealized hedge (gains) losses as set forth in this release represents total operating revenue adjusted for non-cash (gains) losses on unsettled hedges.  Antero believes that revenue excluding unrealized hedge (gains) losses is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Revenue excluding unrealized hedge (gains) losses is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance.  The following table reconciles total operating revenue to revenue excluding unrealized hedge (gains) losses (in thousands):

 

		Three months ended September 30,						Nine months ended September 30,
		2016			2017			2016			2017
Total operating revenue		$	1,116,503		$	647,880		$	1,588,309		$	2,633,848
Hedge (gains) losses		(530,334		)	65,957			(125,624		)	(458,459		)
Cash receipts for settled hedges		196,712			61,479			813,559			137,392
Revenue excluding unrealized hedge (gains) losses		$	782,881		$	775,316		$	2,276,244		$	2,312,781

 

9

 

Adjusted net income (loss) as set forth in this release represents net income (loss), adjusted for certain items.  Antero believes that adjusted net income (loss) is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Adjusted net income (loss) is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance.  The following table reconciles net income (loss) to adjusted net income (loss) (in thousands):

 

		Three months ended						Nine months ended
		September 30,						September 30,
		2016			2017			2016			2017
Net income (loss)		$	238,255		$	(135,063	)	$	(363,044	)	$	128,201
Hedge (gains) losses		(530,334		)	65,957			(125,624		)	(458,459		)
Cash receipts for settled hedges		196,712			61,479			813,559			137,392
Impairment of unproved properties		11,753			41,000			47,223			83,098
Equity-based compensation		26,381			26,447			75,667			78,925
Income tax effect of reconciling items		112,490			(73,735		)	(308,675		)	60,175
Adjusted net income (loss)		$	55,257		$	(13,915	)	$	139,106		$	29,332

 

Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital items.  Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt.  Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry.  In turn, many investors use this published research in making investment decisions.  Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.

 

The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release (in thousands):

 

		Three months ended September 30,						Nine months ended September 30,
		2016			2017			2016			2017
Net cash provided by operating activities		$	326,991		$	1,045,222		$	905,697		$	1,692,808
Net change in working capital		(17,327		)	(29,899		)	(35,939		)	(130,089		)
Cash flow from operations before changes in working capital		$	309,664		$	1,015,323		$	869,758		$	1,562,719

 

The following table reconciles total debt to net debt on a consolidated basis and a stand-alone E&P basis (in thousands):

 

		December 31,			September 30,
		2016			2017
AR Bank credit facility		$	440,000		$	25,000
AM Bank credit facility		210,000			427,000
5.375% AR senior notes due 2021		1,000,000			1,000,000
5.125% AR senior notes due 2022		1,100,000			1,100,000
5.625% AR senior notes due 2023		750,000			750,000
5.375% AM senior notes due 2024		650,000			650,000
5.000% AR senior notes due 2025		600,000			600,000
AR net unamortized premium		1,749			1,588
AR net unamortized debt issuance costs		(37,690		)	(33,789		)
AM net unamortized debt issuance costs		(10,086		)	(9,278		)
Consolidated total debt		$	4,703,973		$	4,510,521
Less: AR cash and cash equivalents		17,568			21,199
Less: AM cash and cash equivalents		14,042			2,495
Consolidated net debt		$	4,672,363		$	4,486,827
Stand-alone E&P net debt		$	3,836,491		$	3,421,600

 

10

 

Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income from continuing operations including noncontrolling interest after adjusting for those items shown in the table below.  Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP.  Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP.  Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.  Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations.  However, Antero’s management team believes Adjusted EBITDAX is useful to an investor in evaluating the Company’s financial performance because this measure:

 

·                  is widely used by investors in the oil and gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;

 

·                  helps investors to more meaningfully evaluate and compare the results of Antero’s operations from period to period by removing the effect of its capital structure from its operating structure; and

 

·                  is used by the Company’s management team for various purposes, including as a measure of operating performance, in presentations to its Board of Directors, as a basis for strategic planning and forecasting.  Adjusted EBITDAX is also used by our Board of Directors as a performance measure in determining executive compensation.  Adjusted EBITDAX, as defined by our credit facility, is used by our lenders pursuant to covenants under our revolving credit facility and the indentures governing the Company’s senior notes.

 

There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero’s net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies.  The following tables represent a reconciliation of the Company’s net income (loss) from continuing operations including noncontrolling interest to Adjusted EBITDAX, a reconciliation of Adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled hedges to Adjusted EBITDAX margin (in thousands except Adjusted EBITDAX margin).

 

		Three months ended						Nine months ended
		September 30,						September 30,
		2016			2017			2016			2017
Net income (loss) including noncontrolling interest		$	268,196		$	(90,000	)	$	(296,644	)	$	255,523
Commodity derivative (gains) losses		(530,334		)	65,957			(125,624		)	(458,459		)
Gains on settled derivative instruments		196,712			61,479			813,559			137,392
Interest expense		59,755			70,059			185,634			205,311
Income tax expense (benefit)		140,924			(45,078		)	(230,755		)	105,087
Depreciation, depletion, amortization, and accretion		199,741			207,626			589,903			612,823
Impairment of unproved properties		11,753			41,000			47,223			83,098
Exploration expense		1,166			1,599			3,289			5,510
Equity-based compensation expense		26,381			26,447			75,667			78,925
Equity in earnings of unconsolidated affiliate		(1,543		)	(7,033		)	(2,027		)	(12,887		)
Distributions from unconsolidated affiliates		—			4,300			—			10,120
State franchise taxes		—			—			39			—
Consolidated Adjusted EBITDAX		372,751			336,356			1,060,264			1,022,443
Interest expense		(59,755		)	(70,059		)	(185,634		)	(205,311		)
Exploration expense		(1,166		)	(1,599		)	(3,289		)	(5,510		)
Changes in current assets and liabilities		17,327			29,899			35,939			130,089
State franchise taxes		—			—			(39		)	—
Proceeds from derivative monetization		—			749,906			—			749,906
Other non-cash items		(2,166		)	719			(1,544		)	1,191
Net cash provided by operating activities		$	326,991		$	1,045,222		$	905,697		$	1,692,808

 

11

 

		Three months ended						Nine months ended
		September 30,						September 30,
		2016			2017			2016			2017
Adjusted EBITDAX margin ($ per Mcfe):
Realized price before cash receipts for settled hedges		$	2.82		$	3.10		$	2.36		$	3.30
Gathering, compression, water handling and treatment revenues		0.01			0.01			0.03			0.01
Distributions from unconsolidated affiliates		—			0.02			—			0.02
Lease operating expense		(0.08		)	(0.11		)	(0.08		)	(0.09		)
Gathering, compression, processing and transportation costs		(1.36		)	(1.32		)	(1.32		)	(1.35		)
Marketing, net		(0.10		)	(0.13		)	(0.19		)	(0.13		)
Production taxes		(0.09		)	(0.11		)	(0.11		)	(0.12		)
General and administrative(1)		(0.18		)	(0.17		)	(0.20		)	(0.18		)
Adjusted EBITDAX margin before settled hedges		$	1.02		$	1.29		$	0.49		$	1.46
Cash receipts for settled hedges		1.14			0.29			1.66			0.23
Adjusted EBITDAX margin ($ per Mcfe):		$	2.16		$	1.58		$	2.15		$	1.69

 

(1)   Excludes equity-based stock compensation

 

The following table reconciles Antero’s consolidated net income to consolidated Adjusted EBITDAX for the twelve months ending September 30, 2017 as used in this release (in thousands):

 

		Twelve months ended
		September 30,
		2017
Net loss including noncontrolling interest		$	(197,281	)
Commodity derivative losses		181,346
Net cash receipts on settled derivative instruments		326,916
Gain on sale of assets		(97,635		)
Interest expense		273,229
Loss on early extinguishment of debt		16,956
Income tax benefit		(160,534		)
Depreciation, depletion, amortization and accretion		835,266
Impairment of unproved properties		198,810
Exploration expense		9,083
Equity-based compensation expense		105,679
Equity in earnings of unconsolidated affiliates		(11,345		)
Distributions from unconsolidated affiliates		17,822
State franchise taxes		11
Total Adjusted EBITDAX		$	1,498,323

 

12

 

“Stand-alone E&P Adjusted EBITDAX” is also used by our management team for various purposes, including as a measure of operating performance of our exploration and production and marketing segments and as a basis for strategic planning and forecasting.  Stand-alone E&P Adjusted EBITDAX is a non-GAAP financial measure that we define as operating income or loss before derivative fair value gains or losses from exploration and production and marketing (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, and gain or loss on changes in the fair value of contingent acquisition consideration.  Stand-alone E&P Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units.  Operating income or loss represents net income or loss, including noncontrolling interests, before interest expense and interest income, income taxes, and equity in earnings of unconsolidated affiliates.  Operating income is the most directly comparable GAAP financial measure to Stand-alone E&P Adjusted EBITDAX because we do not account for income tax expense or interest expense on a segment basis.

 

The following table reconciles operating income to total Adjusted EBITDAX on a stand-alone E&P basis. Stand-alone E&P basis includes operations from both the exploration and production segment and marketing segment (in thousands):

 

		Twelve months ended
		September 30,
		2017
Stand-alone E&P operating loss		$	(235,777	)
Commodity derivative gains		181,346
Net cash receipts on settled derivatives instruments		326,916
Depreciation, depletion, amortization and accretion		719,999
Impairment of unproved properties		198,810
Exploration expense		9,083
Change in fair value of contingent acquisition consideration		(15,777		)
Equity-based compensation expense		78,560
Gain on sale of assets		(93,776		)
State franchise taxes		11
Distributions from limited partner interest in Antero Midstream		126,833
Stand-alone E&P Adjusted EBITDAX		$	1,296,228

 

13

 

The following table reconciles Antero Midstream’s net income to Adjusted EBITDA and distributable cash flow as used in this release (in thousands):

 

		Three months ended
		September 30,
		2016			2017
Net income		$	70,524		$	80,893
Interest expense		5,303			9,311
Depreciation expense		26,136			30,556
Accretion of contingent acquisition consideration		3,527			2,556
Equity-based compensation		6,599			7,199
Equity in earnings of unconsolidated affiliates		(1,544		)	(7,033		)
Distributions from unconsolidated affiliates		—			4,300
Adjusted EBITDA		$	110,545		$	127,782
Interest paid		(4,043		)	(20,554		)
Decrease in cash reserved for bond interest (1)		—			8,831
Cash reserved for payment of income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards(2)		(1,000		)	(1,500		)
Cash distribution to be received from unconsolidated affiliate		2,221			—
Maintenance capital expenditures(3)		(4,638		)	(10,771		)
Distributable cash flow		$	103,085		$	103,788
Distributions Declared to Antero Midstream Holders
Limited Partners		$	47,025		$	63,454
Incentive distribution rights		4,820			19,067
Total Aggregate Distributions		$	51,845		$	82,521
DCF coverage ratio		2.0x			1.3x

 

(1)         Cash reserved for bond interest expense on Antero Midstream’s 5.375% senior notes outstanding during the period that is paid on a semi-annual basis on March 15th and September 15th of each year.

(2)         Estimate of current period portion of expected cash payment for income tax withholding attributable to vesting of Midstream LTIP equity-based compensation awards to be paid in the fourth quarter.

(3)         Maintenance capital expenditures represent the portion of our estimated capital expenditures associated with (i) the connection of new wells to our gathering and processing systems that we believe will be necessary to offset the natural production declines Antero Resources will experience on all of its wells over time, and (ii) water delivery to new wells necessary to maintain the average throughput volume on our systems.

 

Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company’s website is located at www.anteroresources.com.

 

This release includes “forward-looking statements”.  Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero’s control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

 

Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A. Risk Factors” in Antero’s Annual Report on Form 10-K for the year ended December 31, 2016.

 

For more information, contact Michael Kennedy — SVP — Finance, at (303) 357-6782 or mkennedy@anteroresources.com.

 

14

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, 2016 and September 30, 2017

(unaudited)

(In thousands, except per share amounts)

 

		December 31, 2016			September 30, 2017
Assets
Current assets:
Cash and cash equivalents		$	31,610		23,694
Accounts receivable, net of allowance for doubtful accounts of $1,195 and $1,320 at December 31, 2016 and September 30, 2017, respectively		29,682			43,854
Accrued revenue		261,960			233,585
Derivative instruments		73,022			299,796
Other current assets		6,313			10,024
Total current assets		402,587			610,953
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties		2,331,173			2,305,749
Proved properties		9,549,671			10,779,043
Water handling and treatment systems		744,682			891,869
Gathering systems and facilities		1,723,768			1,977,510
Other property and equipment		41,231			54,571
		14,390,525			16,008,742
Less accumulated depletion, depreciation, and amortization		(2,363,778		)	(2,973,544	)
Property and equipment, net		12,026,747			13,035,198
Derivative instruments		1,731,063			876,293
Investments in unconsolidated affiliates		68,299			287,842
Other assets		26,854			38,928
Total assets		$	14,255,550		14,849,214
Liabilities and Equity
Current liabilities:
Accounts payable		$	38,627		47,457
Accrued liabilities		393,803			429,696
Revenue distributions payable		163,989			220,971
Derivative instruments		203,635			4,285
Other current liabilities		17,334			15,267
Total current liabilities		817,388			717,676
Long-term liabilities:
Long-term debt		4,703,973			4,510,521
Deferred income tax liability		950,217			1,180,564
Derivative instruments		234			427
Other liabilities		55,160			52,764
Total liabilities		6,526,972			6,461,952
Commitments and contingencies
Equity:
Stockholders’ equity:
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued		—			—
Common stock, $0.01 par value; authorized - 1,000,000 shares; 314,877 shares and 315,470 shares issued and outstanding at December 31, 2016 and September 30, 2017, respectively		3,149			3,155
Additional paid-in capital		5,299,481			6,564,320
Accumulated earnings		959,995			1,088,196
Total stockholders’ equity		6,262,625			7,655,671
Noncontrolling interests in consolidated subsidiary		1,465,953			731,591
Total equity		7,728,578			8,387,262
Total liabilities and equity		$	14,255,550		14,849,214

 

15

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Three Months Ended September 30, 2016 and 2017

(unaudited)

(In thousands, except per share amounts)

 

		Three Months Ended September 30,
		2016			2017
Revenue:
Natural gas sales		$	364,373		409,141
Natural gas liquids sales		106,958			224,533
Oil sales		14,793			26,527
Gathering, compression, water handling and treatment		2,969			2,869
Marketing		97,076			50,767
Commodity derivative fair value gains (losses)		530,334			(65,957	)
Total revenue		1,116,503			647,880
Operating expenses:
Lease operating		13,854			23,491
Gathering, compression, processing, and transportation		234,915			282,134
Production and ad valorem taxes		15,554			22,995
Marketing		114,611			78,884
Exploration		1,166			1,599
Impairment of unproved properties		11,753			41,000
Depletion, depreciation, and amortization		199,113			206,968
Accretion of asset retirement obligations		628			658
General and administrative (including equity-based compensation expense of $26,381 and $26,447 in 2016 and 2017, respectively)		57,577			62,203
Total operating expenses		649,171			719,932
Operating income (loss)		467,332			(72,052	)
Other income (expenses):
Equity in earnings of unconsolidated affiliates		1,543			7,033
Interest		(59,755		)	(70,059	)
Total other expenses		(58,212		)	(63,026	)
Income (loss) before income taxes		409,120			(135,078	)
Provision for income tax (expense) benefit		(140,924		)	45,078
Net income (loss) and comprehensive income (loss) including noncontrolling interests		268,196			(90,000	)
Net income and comprehensive income attributable to noncontrolling interests		29,941			45,063
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation		$	238,255		(135,063	)
Earnings (loss) per common share—basic		$	0.78		(0.43	)
Earnings (loss) per common share—assuming dilution		$	0.77		(0.43	)
Weighted average number of shares outstanding:
Basic		306,785			315,463
Diluted		308,657			315,463

 

16

 

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Nine Months Ended September 30, 2016 and 2017

(unaudited)
(In thousands, except per share amounts)

 

		Nine Months Ended September 30,
		2016			2017
Revenue and other:
Natural gas sales		$	848,936		1,330,062
Natural gas liquids sales		274,736			590,004
Oil sales		41,712			79,999
Gathering, compression, water handling and treatment		10,107			8,665
Marketing		287,194			166,659
Commodity derivative fair value gains		125,624			458,459
Total revenue and other		1,588,309			2,633,848
Operating expenses:
Lease operating		37,190			56,034
Gathering, compression, processing, and transportation		649,713			815,710
Production and ad valorem taxes		52,296			70,341
Marketing		378,521			246,298
Exploration		3,289			5,510
Impairment of unproved properties		47,223			83,098
Depletion, depreciation, and amortization		588,057			610,879
Accretion of asset retirement obligations		1,846			1,944
General and administrative (including equity-based compensation expense of $75,667 and $78,925 in 2016 and 2017, respectively)		173,966			191,000
Total operating expenses		1,932,101			2,080,814
Operating income (loss)		(343,792		)	553,034
Other income (expenses):
Equity in earnings of unconsolidated affiliates		2,027			12,887
Interest		(185,634		)	(205,311	)
Total other expenses		(183,607		)	(192,424	)
Income (loss) before income taxes		(527,399		)	360,610
Provision for income tax (expense) benefit		230,755			(105,087	)
Net income (loss) and comprehensive income (loss) including noncontrolling interests		(296,644		)	255,523
Net income and comprehensive income attributable to noncontrolling interests		66,400			127,322
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation		$	(363,044	)	128,201
Earnings (loss) per common share—basic		$	(1.26	)	0.41
Earnings (loss) per common share—assuming dilution		$	(1.26	)	0.41
Weighted average number of shares outstanding:
Basic		288,607			315,275
Diluted		288,607			316,140

 

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